Journal articles on the topic 'Geology, Stratigraphic. Physical geology Frontier formation'

Analysis of the sedimentology and stratigraphic architecture of tightly spaced three dimensional outcrops reveals that the Turonian (Upper Cretaceous) Wall Creek Member of the Frontier Formation in the western Powder River Basin, Wyoming, USA, is not composed of one continuous coarsening upward succession but of a complex stacked delta system containing three distinct sequences (S1-S3), each with a unique facies distribution and architectural heterogeneity. The basal sequence S1 consists of a fluvial dominated delta with two distinct lobes. These lobes are spatially constrained to the northeastern study area and show a rapid facies transition from trough crossbedded mouthbar deposits to lower delta front turbidites. Low angle clinoforms suggest a low accommodation setting with main sediment transport to the south. The middle S2 sequence is common throughout the study area and contains an abundance of storm-derived deposits, including hummocky cross stratification, suggesting the transition to a wave and storm-dominated delta setting. Sediment transport is largely to the south controlled by wind induced shear stresses. Lastly, heterolithic trough crossbedded sandstones with flaser bedding and abundant thin mudstones and rip-up clasts are characteristic for sequence S3. These deposits are interpreted as tidal bars in a tidal influenced delta. Quantitative evaluation of facies in the Wall Creek Member sequences shows that the dimensions and connectivity (baffle or barrier competence) of fine-grained thin beds varies systematically within the three delta types. The S1 fluvial delta is largely composed of laterally continuous delta front turbidites with continuous fine-grained thin beds (mean length 21.1 m or 69.2 ft, max length 83.9 m or 275.2 ft) separating individual sandstone beds. Conversely, abundant bioturbation and intense scouring by storms results in high amalgamation of sandy beds in sequence S2 and a limited length of fine-grained thin beds (mean 8.5 m or 27.9 ft) in the wave-dominated delta sequence. Tidally influenced deposits of sequence S3 are largely composed of heterolithic trough crossbedded sandstones and mudstones with low bioturbation, resulting in an intermediate fine-grained thin bed deposit (mean 12.1 m or 39.7 ft).

The Neoproterozoic–Palaeozoic transition (NPT) around 600 Ma ago was a critical time interval when the Earth experienced fundamental change, manifested as climatic extremes – ‘snowball Earth’ – followed by the emergence and rapid diversification of animals – ‘Cambrian explosion’. How animals and environments co-evolved, and what caused these fundamental changes to the Earth system during the NPT, is a great scientific puzzle, which has been a rapidly developing frontier of interdisciplinary research between bio- and geosciences. South China preserves a complete stratigraphic succession of the NPT developed in various facies ranging from shallow to deep marine realms with extraordinarily well-preserved, successive fossil biotas in various taphonomic settings (Zhu, 2010; Fig. 1), making it a key area and global focus of studies in the field over recent decades. Indeed, the current narrative of early animal evolution has largely been based on the fossil biotas from South China. These include: (1) the world's oldest microscopic animal fossils with cellular details from the early Ediacaran Weng'an biota (Doushantuo Formation); (2) putative macroscopic animal fossils preserved as carbonaceous imprints from the early Ediacaran Lantian, Wenghui and Miaohe biotas (also Doushantuo Formation); (3) typical late Ediacaran faunas, preserved in dark limestone (Shibantan biota) and as large and poorly mineralized tubular animal fossils (Gaojiashan biota), both from the Dengying Formation; (4) phosphatized small shelly and soft-bodied animal fossils from the early Cambrian Meishucun and Kuanchuanpu faunas; and (5) Cambrian fossil Lagerstätten (Chengjiang, Guanshan and Kaili faunas) with typical Burgess Shale-type soft-bodied preservation.

ABSTRACT This geologic study is focused on a less than 5 square-mile (ca. 13 km2) tract of public land in northwestern Wyoming, 8 miles (12.9 km) south-southwest of the small town of Clark in Park County. The study area is south of Clarks Fork of Yellowstone River along the eastern base of the topographic feature called Bald Ridge, also known structurally as Dead Indian monocline. Since the Middle Eocene, the study area has been along the northwestern margin of the Bighorn Basin. Prior to that time, the study area existed near the west–east center of the basin. Bald Ridge became elevated late in the Laramide orogeny (no older than the Early Eocene) through east-directed faulting of basement rocks via the extensive Line Creek–Oregon Basin thrust system. As that active faulting occurred, the overlying Phanerozoic strata (Lower Cambrian through Lower Eocene) responded with numerous west-directed, out-of-the-basin thrusts as a new western-basin margin developed along the eastern realm of the newly born Absaroka volcanic field. Most of that deformation occurred after deposition of uppermost levels of the Lower Eocene Willwood Formation. The key purpose of the present paper was to improve the accuracy of mapping of the Jurassic into Eocene stratigraphy along the newly restricted, northwestern edge of Wyoming’s Bighorn Basin. The stratigraphic column in a north–south band along the eastern flank of the Beartooth Mountains and continuing southward into the present study area was markedly deformed and deeply eroded late during the Laramide orogeny. The present small, more southerly study area is structurally and erosionally simpler than its more northerly equivalent. Thus, its study adds important geological information to the history of the northern Cody Arch, a convex-westward string of related basement-involved uplifts extending southward to southwest of the city of Cody. Progressively steepening eastward dips of strata characterize a west-to-east transect from the summit of Bald Ridge (capped by the shallowly dipping, Mississippian Madison Limestone) to the western edge of strongly overturned outcrops of the Eocene Willwood Formation. The Upper Cretaceous Meeteetse Formation is the stratigraphic horizon at which the dips attain vertical or slightly overturned orientations. All consequential faults within the newly mapped area are thrusts, and they show generally westward (out-of-the-basin) displacements. Despite those west-directed displacements, their primary cause was tectonic shortening at depth below Bald Ridge that was directed to the northeast or east-northeast. During the Laramide orogeny, certain thrust planes within the east-dipping Phanerozoic rock column cut down-section stratigraphically (but uphill relative to Earth’s surface) and thereby placed younger strata upon older. The cumulative result, as recognized at several levels within the present area of study, was marked thinning of the total section. For example, surface exposures of the mostly Paleocene Fort Union Formation, 4,000 feet (1,219 m) thick only 7 miles (11.3 km) to the east, was completely eliminated from the local surface stratigraphy by that means. The northern end of Bald Ridge is formed by the highly asymmetric Canyon Mouth anticline. That structure differs strongly in the attitude of its hinge line from the general east-northeast dip of strata cloaking Bald Ridge. The Canyon Mouth anticline’s hinge line plunges steeply to the southeast, and dips on its northeastern flanks are vertical to partly overturned. Surprisingly, hinge lines and flanks of all other anticlinal/synclinal structures recognized within the present map area share those same orientations with Canyon Mouth anticline. These consistent but unexpected differences in orientation from unfolded strata may represent very late events in the history of Laramide strain vectors across the study area. Working in northern parts of this study area, an independent group determining radiometric ages of detrital-zircon grains reported close agreements in age with their host localities in the Early Cretaceous Mowry Shale and Frontier Formation. However, under the present paper’s interpretation of the local stratigraphy, the other workers misidentified formational hosts for all three samplings. That resulted in age-determination errors of depositional history within the Upper Cretaceous section of as much as 28.8 million years.

ABSTRACT Mass-transport complexes (MTCs), mass-transport deposits (MTDs), and associated facies and features are widely recognized in continental slopes around the world. In most current stratigraphic models of MTCs and MTDs, these submarine sediment failures are related to aquifer outflow (sapping, seepage) along continental slope fronts that originated during relative sea-level fall. We test a hypothetical scenario that is favored during early forced regression using reduced-scale physical simulation. A major underground subaerial hydraulic gradient is assumed to flow towards the basin depocenter as a function of relative sea-level fall. We developed an experimental apparatus with slope angles varying between 15 and 30° to test this concept. Hydraulic gradients, aquifer outflow velocities, and triggered collapses induced by the seepage effect were recorded at various positions of the slope. Analysis shows that steeper slope gradients require lower seepage velocities (and shear stresses) to trigger collapse, but gentler slopes remain unchanged. Experimental data are compatible with a seepage effect that could potentially trigger mass failure and the formation of MTCs during relative sea-level fall. The features produced in the experiment have geometries comparable to natural environments, and the experimental seepage velocities are of an order of magnitude similar to those monitored in submarine aquifers. The experimental results advance understanding of mass transport in continental slopes by introducing and testing new methods, and also provide new insights into potential submarine geohazard risks where tectonic uplift operates along some coastal regions.

The Xujiahe Formation of the Late Triassic in the Western Sichuan Depression contains abundant gas reservoirs. Influenced by the thrust tectonic movement of the foreland basin, the fluvial-delta sedimentary system supplied by multiple provenances formed the Xu2 Formation of the Xinchang area. We used detailed description of drilling wells and cores to define the sequence stratigraphic framework and sand body types. We used stratal slices through the seismic texture model regression (TMR) attribute volume to map the evolution of the sedimentary system and the sand body distribution. Our results indicate that the Xu2 Formation exhibits a complete long-term base-level cycle and that there are six sand body deposit types: distributary channel, interchannel, subaqueous distributary channel, interdistributary bay, mouth bar, and sheet sand. Stratal slices through the seismic TMR attribute volume at different levels map the spatial variation of sand and mudstone, which we use to construct a sedimentary filling evolution model. This model indicates that during the time of deposition of the lower submember, the main provenance supply came from the northwest direction, resulting in the sand bodies mainly being deposited in the west. During the time of deposition of the central submember, the sediment supply was large and came from the northwest and northeast directions, resulting in large, laterally extensive, thick sands. During the time of deposition of the upper submember, the sediment supply was from the northeast direction, with the sand bodies more developed in the east. The flow direction of the (subaqueous-) distributary channels indicate that they migrated from northwest to northeast. There are significant differences in the channel energy, sedimentary characteristics, and reservoir physical properties in the three submembers, which cause differences in oil and gas productivity in the reservoir of the Xu2 Formation. We believe that detailed mapping of the spatial distribution of sedimentary systems can provide critical guidance not only to explore but also to develop in high-quality oil and gas reservoirs such as the Xu2 Formation.

Summary The Ceará Basin is a deepwater exploration frontier basin that comprises part of the Brazilian equatorial margin. This basin has been receiving renewed attention from the petroleum industry since the discovery of important deepwater oil fields in its African counterpart. However, detailed seismic stratigraphic, depositional, and structural frameworks for the Ceará Basin are still lacking in the literature. We have analyzed a series of 2D seismic data sets and stumbled into the pitfalls of migration artifacts (i.e., multiples) ultimately realizing that reprocessing was the best option to avoid the mistake of interpreting these artifacts as geologic features. Multiples can be difficult to identify in seismic data in which they mimic the true geology of the region, and they often present a pitfall for less experienced interpreters. Indeed, the identification and removal of multiples is crucial because they do not reflect the true geology in the subsurface and may otherwise lead to incorrect business decisions. Geological feature: Stratigraphy of the Ceará Basin, offshore Brazil Seismic appearance: Strong seismic horizons mimicking geological layering Alternative interpretations: Multiples arising from poor seismic migration processing Features with similar appearance: Strong seismic horizons reflecting basement and carbonates Formation: Rift sequence of the Ceará Basin Age: Cretaceous Location: Ceará Basin, offshore Brazil Seismic data: Obtained by the Brazilian National Petroleum Agency and reprocessed by the authors Analysis tool: Reprocessing

Based on a High-Resolution 3D seismic block acquired in the Gulf of Lion in 2004–2005 we investigated fluid pipes and pockmarks on the top of the interfluve between the Hérault canyon and the Bourcart canyon both created by turbidity currents and gravity flows from the shelf to the deep basin in the north-western Mediterranean Sea. Combining the geometry of the potential fluid pipes with the induced deformation of surrounding sediments leads then to the ability to differentiate between potential fluid sources (root vs source) and to better estimate the triggering mechanisms (allochtonous vs. autochtonous cause). We linked together a set of derived attributes, such as Chaos and RMS amplitude, to a 3D description of pipes along which fluids may migrate. As previously shown in other basins, the induced deformation, creating cone in cone or V-shaped structures, may develop in response to the fluid pipe propagation in unconsolidated sediments in the near surface. The level at the top of a cone structure is diachronous. It means that stratigraphic levels over this surface are deformed at the end of the migration. They collapse forming a depression called a pockmark. These pipes are the result of repeated cycles of fluid expulsion that might be correlated with rapid sea-level rise instead of sediment loading. The most recent event (MIS 2.2 stage) has led to the formation of a pockmark on the modern seafloor. It has been used as a reference for calculating the effect of a rapid sea-level rise on fluid expulsion. As all physical and geometrical parameters are constrained, we were able to define that a + 34 m of sea level rise may account for triggering fluid expulsion from a very shallow silty-sandy layer at 9 m below seafloor since the last glacial stage. This value is consistent with a sea level rise of about 102 m during this period. This study shows that the episodic nature of fluid release resulted from hydromechanical processes during sea-level rise due to the interactivity between high pressure regimes and principal in situ stresses.

Summary Gas production from the Frontier formation at 18,300-ft depth in the Frewen Deep #4 well, eastern Green River basin (Wyoming), was uneconomic despite the presence of three sets of numerous, partially open, vertical natural fractures. Production dropped from 360 Mcf/D to 140 Mcf/D during a 10-day production test, and the well was abandoned. Examination of the fractures in the core suggests several possible reasons for this poor production. One factor is the presence of mineralization in the fractures. Another more important factor is that the remnant porosity left in the fractures by partial mineralization is commonly plugged with an overmature hydrocarbon residue (pyrobitumen). Reorientation of the in-situ horizontal compressive stress to a trend normal to the main fractures, which now acts to close fracture apertures during reservoir drawdown, is also an important factor. Introduction The Frewen Deep #4 well is located in Sweetwater county, southwestern Wyoming (Section 13 of Township 19 North, Range 95 West). The target of the well was natural gas from sandstones of the Frontier formation (Fig. 1) at a depth of approximately 18,300 ft. The Frontier formation consists of Cretaceous-age sandstones and shales. The main reservoir sandstone is about 40-ft thick at this location, with thick over- and underlying shales. Amoco Production Co. formed the Frewen Deep Unit in 1988. Its purpose was to evaluate the hydrocarbon potential of the Cretaceous sedimentary section in a 16 sq miles area on the south flank of the Wamsutter Arch. This arch trends WNW-ESE and divides the eastern Green River basin into two subbasins, the Great Divide basin to the north and the Washakie basin to the south (Fig. 2A). The Cretaceous sedimentary section is commonly productive in stratigraphic traps along the crestal portion of the Wamsutter Arch, as in the Echo Springs-Standard Draw and Wamsutter fields. The Frewen Deep Unit was formed to explore for deeper production in the Lakota formation. The initial unit well, the Frewen Deep #1, was drilled to a total depth of 19,299 ft on a southward-plunging, fault-related anticline. It was completed in the Lakota formation, but extended production tests from this zone indicated noncommercial rates. Shows had been observed while drilling through the Frontier formation to the deeper horizon, and this zone was targeted for testing. Unfortunately, the wellbore became mechanically unusable during the course of moving uphole to test the Frontier. Mechanical problems associated with the great depth, problems with the completion fluids, as well as problems with the casing integrity in this well were grounds for the decision to evaluate the formation in a completely new well. The Frewen Deep #4 well was drilled as a replacement, offset 600 ft from the #1 well (Fig. 2B). Much of the Frontier formation in the #4 well was cored with good recovery (86 ft), even though the core contains numerous partially mineralized vertical natural fractures. The fractures have obvious open porosity at depth (Fig. 3), with bridgings of mineralization holding open apertures locally up to 5 mm wide. Four fracture sets, based on character and strike, were differentiated in the core. These included three sets of irregular but numerous natural fractures, designated F1, F2, and F3 in order of their formation (based on observed cross-cutting relationships). The 86 ft of core had been slabbed and extensively sampled before our study, and the fractures themselves are commonly multistranded. Both of these factors make exact fracture counts difficult to obtain. Pervasive fracturing of the core suggests that the reservoir must be highly fractured, although the actual data set consists of approximately 10 F1 fractures, eight F2 fractures, and two F3 fractures. Fracture heights along the vertical axis of the core range from a maximum of about 4 ft for the F1 fractures down to several inches for F3 fractures. A fourth set of fractures consists of 30 regularly spaced, coring-induced1 petal fractures striking parallel to each other and to the F3 fractures. Gas in the drilling mud and the presence of open fractures seemed to promise significant gas production, but the initial production rate was not high and declined precipitously to an uneconomic level. We analyzed the natural and coring-induced fractures in the Frewen core during this study to assess the possible reasons for the low and declining production despite the presence of significant natural fracturing in the reservoir. This paper documents the conclusions from the core study and also offers an interpretation for the origin of these unusual fractures. Well History and Reservoir Properties. The Frewen Deep #4 well was spudded on 18 October 1990 and reached a total depth of 18,600 ft on 3 March 1991. Three separate conventional cores (totaling 86 ft recovered) were taken through the Frontier formation. Horizontal Dean Stark air permeabilities were measured at each foot in the sandstone core; 61 measurements yielded an average permeability of 0.007 md (range 0 to 1.23 md), an average porosity of 3.7% (range 0.8 to 7.1%), and a flow capacity of 1.7 md-ft. Geophysical logs were collected over the objective interval, including induction and neutron/density suites. Mud weight at total depth was in excess of 15 ppg, indicating a pressure of approximately 14,489 psi (minimum) at the reservoir level. Shows of gas requiring the use of a gas buster to de-gas the mud began at 18,225 ft and continued during coring operations. Shows periodically supported 10- to 20-ft (estimated) flares. Below 18,380 ft, the mud did not require de-gassing to remain manageable and control the well. Multiple sets of casing were set in anticipation of high pressures: we set 13 3/8-in. surface casing at 2,358 ft, 9 5/8-in. intermediate casing at 10,835 ft, and 51/2-in. casing at 18,114 ft before initiating coring operations. A 5-in. liner set from 18,114 to 18,593 ft completed the casing of the well. Each of the casing and liner strings was cemented in place and an acceptable bond was achieved. Completion operations began on 23 April 1991 when the well was perforated from 18,316 to 18,344 ft with 6 shots per foot, 6,000 psi underbalanced. The well did not flow. Swabbing was required to achieve a 15 to 20 Mcf/D flow rate for 7 days. Subsequently, we performed a CO2 breakdown, with 110 tons CO2 pumped at 8.5 bbl/min into 14,400 psi tubing pressure. The well flowed back CO2 and gas at a rate of 500 Mcf/D (>25% CO2) and was shut in preparatory to flow testing and bottomhole pressure buildup.

AbstractDue to their particularly good mechanical and self-healing properties combined with exceptionally efficient cation adsorbents and exchanger capacities, clay minerals and clay rock formations are considered as suitable geological barriers for radioactive waste disposal. The Middle Jurassic Opalinus Clay Formation has been identified as a potential host rock. Logging data were measured at the Benken borehole drilled through this formation in northern Switzerland. This paper presents a statistical methodology to improve the description of the physical properties of the clay rock based on the well-log data. The methodology involves the classification of a set of local statistics, calculated from a reduced number of principal components computed from well-log properties. The use of a kernel-based method to calculate local statistics allows an analysis of spatial variability to be carried out at different scales, and with different scale effects. The first-order layering was found to be robust and independent of kernel size (i.e. observation scale), while preserving small-scale heterogeneities that are useful for further interpretation. The log units can be more clearly interpreted in terms of stationary or transitional log units, depending on the behaviour of local statistics. Finally, the derived spatial variability of the log-units properties are compared with earlier lithological descriptions and stratigraphic data.

Abstract Introduction. It is believed that an inlandsis covered the northern half of the African Gondwana at the end of the Ordovician. After a review of the stratigraphic framework and the methodology used, an attempt is made to reconstruct the successive stages of the advance of the sea at the end of the Ordovician and in the early Silurian in a region believed to have been close to the pole. Only the Algerian Sahara is taken in consideration (fig. 1). Some suggestions are made on the role of the glacio-eustatism in the « Silurian » transgression of the Algerian Sahara. Lithostratigraphy. Because of an inadequate biostratigraphy and facies variations in the uppermost Ordovician of Sahara, several lithostratigraphic successions have been proposed. To emphasize the more important features of the glaciation, a generalized lithological column has been prepared [Legrand, 1999] (fig. 2). The biostratigraphical framework. Graptolites are the classical fossils used to construct the biostratigraphy of the uppermost Ordovician and the Lower Silurian. In the Algerian Sahara, the use of the standard graptolite zones has been handicaped by the fact that graptolite faunas are endemic and the typical, diagnostic species occurring in this interval of geologic time are absent. A new regional biostratigraphy had to be constructed based on the diplograptid graptolites present [Legrand, 1999]. The new zones are essentially distribution zones. Brachiopods and chitinozoans have also been used as additional correlating tools. Based on the new graptolite zonation, and the recorded sedimentary events of the region, such as transgressions, regressions and so on, new regional stages and substages have been defined (fig. 3) allowing us to reconstruct the paleogeographic evolution of the Algerian Sahara. Problems with the uppermost Ordovician. The uppermost Ordovician, as herein defined, comprises all the strata belonging to the n4 regional subsystem of the Saharan stratigraphy. This subsystem includes all the “glacial” formations disconformably laid down on the Saharan platform before the beginning of the Silurian. Many problems have been encountered with the uppermost Ordovician of the Algerian Sahara and adjacent regions, but only are considered in this paper : (a) epeirogenic movements and erosion ; (b) the nature of the glacial, periglacial, deltaic and fluviatile sediments ; (c) one glaciation, multiple glaciations or only a polyphase glaciation ; (d) the varying importance of unconformities ; (e) the age of the uppermost Ordovician formations, i.e. whether they are uppermost Ashgillian or upper Caradocian-upper Ashgillian and the precise age of the last Hirnantia fauna. In this paper only the hypothesis of one late Ashgillian glaciation is taken into consideration. Paleogeography of the latest Ordovician (regional subsystem n4). Stage n4a (Cautleyan p.p. and Rawtheyan p.p.). The exact time of the beginning of glaciation is uncertain. Stage n4b (upper Rawtheyan-earliest Hirnantian) (fig. 5). At Djado, shales with the graptolite “Glyptograptus” ojsuensis overlie the glacial strata. Trinucleidae trilobites attest to the withdrawal of the ice followed by a marine transgression in this region. Elsewhere, because of the lack of biostratigraphic data, nothing is definitely known as to what went on in the Algerian Sahara. One may suppose that the ice sheet went on growing in some regions and continental deposits may help in dating this period. Substage n4c1 (early and mid-Hirnantian) (fig. 5). One may suppose that the ice sheet advanced and regressed several times before beginning to melt and the continent began to rebound. However, there are some remarkable regional differences. In the Djado area, the silty-argillaceous sedimentation went on, locally interrupted, perhaps, by the return of glacial sedimentation. Farther north, at Oued In Djerane, the last dropstone shales are replaced by normal, marine graptolitebearing shales, while elsewhere the upper sandstones of the Felar-Felar formation, consisting of more or less continental periglacial facies with “cordons” are deposited. The return to marine, littoral conditions is represented by the Hirnantia– or Plectothyrella-bearing sandstones extending from the Ougarta Mountains to the central Tassili N’ Ajjer. Locally, fluviatile beds mark the end of Ordovician sedimentation. Substage n4c2 (Late Hirnantian) (fig. 6). A new transgression begins with this sub-stage, marking the true beginning of the « Silurian » transgression. It should be noted that it is quite possible that the Hirnantia- and Plectothyrella-bearing sandstone dated as marking the end of substage n4c1 could also indicate the beginning of substage n4c2. Paleogeography of the early Silurian (regional subsystem g1) Lower Llandovery. Substages g1a1, g1a2–3 (lower Rhuddanian) (fig. 7). The substage g1a1 is characterized by the local P. (?) kiliani Zone, which approximately corresponds to the A. ascensus Zone of the classical zonation of the Silurian. The sub-stage g1a2–3 is characterized by the presence of endemic graptolite species of the genus Neodiplograptus believed to correlate the Pk. acuminatus zone of the British zonation. Strata attributed to these substages are common in the western Tassili N’Ajjer, the Tassili of Tafassas-set and the Tassili Ouan Ahaggar. At the Oued In Djerane, the first substage begins with a return to argillaceous sedimentation in an anoxic environment. The second substage is marked by a local regression and the beginning of a northward transgression. Remnants of this substage are present in the eastern Tassili Ouan Ahaggar. Substage g1a4 (upper Rhuddanian) (figs. 8 & 9). This substage holds the sedimentary record of an important phase of the Silurian marine transgression. In the eastern Tassili N’Ajjer, strata assigned to this substage gradually overlie the Ordovician and extend far northwards becoming thinner by progressive transgression – and not because of erosion – to disappear finally south of Al Awaynat (Serdeles). Strata referred to this substage occur also in the eastern Tassili Ouan Ahaggar as far as Ted-jert and possibly In Guezzam. Remnants of this substage occur also, but as outlayers, near the mole of Amguid, at Ers Oum El Lil, Tassili of Tarit and Adrar Tikkadouine. In the area of Bled el Mass the last meters of the Aïn ech Cheikr sandstones are attributed to this substage. Beds of this age are not known on the northern border of the Eglab with the possible exception of the region of El Rhers to the west of Bou Bernous. Middle Llandovery [according to Toghill, 1968 - Legrand, 1996]. Stage g1b (in part Aeronien) (figs. 10 & 11). The middle Llandovery marks the return to marine sedimentation along the Algerian-Libyan border after a short regression at the end of the early Llandovery. The sea covered many parts of the Tassili Ouan Ahaggar. In the east, a regression clearly took place. On the other hand, the extension of the sea to the west, beyond In Guezzam, appears to overlap the preceding substage. In the central Tassili N’Ajjer, a transgression probably took place after an emergence at the end of the Ordovician. This transgression seems to be part of the process already observed farther east in the preceding substages during which the sea appears to abandon a domain after having invaded another one. Thus this transgression appears to correspond to the regression on the Algerian-Libyan frontier and in the eastern Tassili Ouan Ahaggar. All this leads us to think that at this time the sea covered much of the Ahaggar. The middle Llandovery reappears in the Bled el Mass (Aïn ech Cheikr) and core data indicate that it is also present in the eastern limit of the Tanezrouft. The transgression on the northern border of the Eglab probably began at this time, with the possible exception of the region of El Rhers to the west of Bou Bernous, where it was of a very short duration. Upper Llandovery [according to Toghill, 1968 - Legrand, 1996]. Stages g1c, g2a, g2b (in part Aeronian, Telychian). The movements of the sea and the evolution of the sedimentation initiated at the lower and middle Llandovery continue during the upper Llandovery. Conclusion. Many questions can be asked on the development of an inlandsis centered on Africa at the end of the Ordovician. On the question of the melting of the inlandsis, things are somewhat clearer. Everything, or almost everything, took place before the end of the Ordovician. The « microconglomeratic clays » began probably to settle during the stability phase of the inlandsis. The melting of the inlandsis was accompanied by the accumulation of « microconglomeratic » clays, followed by silty clays. The resulting sea level rise caused a transgression from North to South. This rise was compensated by the accumulation of sediments and the glacial rebound causing the filling of the basins. The movements of the sea did not stop because the filling-up of the available space predicted by the principle of accomodation is constantly called into question by subsidence and epeirogenic movements. The mode and the time of formation of the Hoggarian basin are very much in the realm of hypothesis. Traces attributed to it are many in the east, as are those indicating a communication to the north. The sea invaded first the depressed zones of the southeastern Sahara to finally overflow them much like a wave, following the principle of sedimentary accumulation and the rebounding of the hinterland (the hypothesis of forced transgression of Legrand [1999]). All this demands some epirogenic adjustements. The marine domain expanded during the early Silurian in a northwesterly direction, but it appears to have contracted to the east, which was invaded mostly by marine sands. Thus the Silurian transgression, which is less the result of glacioeustatism than is generally admitted, progressed from the southeast to the northwest or locally from the south to the north (from the Hoggar basin), and not from the north to the south as one may have logically supposed (fig. 12). Naturally the irregular topography left from the older relief may have perturbed its progression to the north and northwest.

The Øresund Basin in the transnational area between Sweden and Denmark forms a marginal part of the Danish Basin. The structural outline and stratigraphy of the Mesozoic succession is described, and a novel interpretation and description of the subsurface geology and geothermal potential in the North Sjælland Half-graben is presented. The subsurface bedrock in the basin includes several Mesozoic intervals with potential geothermal sandstone reservoirs. Parts of the succession fulfill specific geological requirements with regard to distribution, composition and quality of the sandstones. A characterisation of these is presently of great interest in the attempt to identify geothermal reservoirs suitable for district heating purposes. The results presented in this paper include for the first time a comprehensive description of the stratigraphic intervals as well as the characteristics of the potential Mesozoic geothermal reservoirs in the Øresund region, including their distribution, composition and physical properties. This is illustrated by seismic cross-sections and well sections. In addition, results from analyses and evaluations of porosity, permeability, formation fluids and temperature are presented. Six potential geothermal reservoirs in the Mesozoic succession are described and assessed. Primary focus is placed on the characteristics of the reservoirs in the Lower Triassic and Rhaetian–Lower Jurassic succession. The study shows that the Mesozoic reservoir sandstones vary considerably with respect to porosity and permeability. Values range between 5–25% for the pre-Rhaetian Triassic sandstones and are commonly >25% for the Rhaetian–Lower Jurassic and Lower Cretaceous sandstones. The corresponding permeability rarely reaches 500 mD for the pre-Rhaetian Triassic reservoirs, while it is commonly above one Darcy for the Rhaetian–Lower Jurassic and the Lower Cretaceous sandstones. The interpreted formation temperatures are 45–50°C at 1500 m, 60–70°C at 2000 m and 70–90°C at 2500 m depth. The combined results provide a geological framework for making site-specific predictions regarding appraisal of viable geothermal projects for district heating purposes in the region as well as reducing the risk of unsuccessful wells.

Abstract. Near-surface geophysical imaging of alluvial fan settings is a challenging task but crucial for understating geological processes in such settings. The alluvial fan of Ghor Al-Haditha at the southeast shore of the Dead Sea is strongly affected by localized subsidence and destructive sinkhole collapses, with a significantly increasing sinkhole formation rate since ca. 1983. A similar increase is observed also on the western shore of the Dead Sea, in correlation with an ongoing decline in the Dead Sea level. Since different structural models of the upper 50 m of the alluvial fan and varying hypothetical sinkhole processes have been suggested for the Ghor Al-Haditha area in the past, this study aimed to clarify the subsurface characteristics responsible for sinkhole development.For this purpose, high-frequency shear wave reflection vibratory seismic surveys were carried out in the Ghor Al-Haditha area along several crossing and parallel profiles with a total length of 1.8 and 2.1 km in 2013 and 2014, respectively. The sedimentary architecture of the alluvial fan at Ghor Al-Haditha is resolved down to a depth of nearly 200 m at a high resolution and is calibrated with the stratigraphic profiles of two boreholes located inside the survey area.The most surprising result of the survey is the absence of evidence of a thick (> 2–10 m) compacted salt layer formerly suggested to lie at ca. 35–40 m depth. Instead, seismic reflection amplitudes and velocities image with good continuity a complex interlocking of alluvial fan deposits and lacustrine sediments of the Dead Sea between 0 and 200 m depth. Furthermore, the underground section of areas affected by sinkholes is characterized by highly scattering wave fields and reduced seismic interval velocities. We propose that the Dead Sea mud layers, which comprise distributed inclusions or lenses of evaporitic chloride, sulfate, and carbonate minerals as well as clay silicates, become increasingly exposed to unsaturated water as the sea level declines and are consequently destabilized and mobilized by both dissolution and physical erosion in the subsurface. This new interpretation of the underlying cause of sinkhole development is supported by surface observations in nearby channel systems. Overall, this study shows that shear wave seismic reflection technique is a promising method for enhanced near-surface imaging in such challenging alluvial fan settings.

Summary A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2), a produced gas (containing 15 mol?% CO2 in CH4), and pure CO2 . The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada. PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods. Introduction A sizable number of heavy-oil reservoirs in Canada1 and in other parts of the world are thin and shaly. Some of these reservoirs are also characterized by low-oil saturation, heterogeneity, low permeability, and bottom water.2,3 For example, about 55% of 1.7 billion m3 of proven heavy-oil resource in the Lloydminster and Kindersley region in Saskatchewan, Canada, is contained in less than 5 m (15 ft.) pay zone and nearly 97% is in less than 10 m (30 ft.) pay zone.4,5 Primary and secondary methods combined recover only about 7% of the proven initial oil in place (IOIP).1 Such reservoirs are not amenable to thermal recovery methods: heat is lost excessively to surroundings and steam is scavenged by bottomwater zones.6,7 The immiscible gas displacement appears to be a very promising enhanced oil recovery (EOR) process for these thin reservoirs. The immiscible gas EOR process has the potential to access more than 90% of the total IOIP.1,7 It could, according to previous studies,6–12 recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. For the development of a viable immiscible gas process applicable to moderately viscous heavy oils found in this sort of reservoirs, we selected three injection gases for study: CO2 reservoir-produced gas (RPG), and flue gas (FG) from power plant exhausts. Extensive literature is available on CO2 flooding for heavy-oil recovery, dealing with pressure/volume/temperature (PVT) behavior,3,6,7,13-15 oil recovery characteristics from linear and scaled models,3,6-8,10-12,15,16 numerical simulation, and field performance.17–19 However, only limited data are available on flue gas and produced gas flooding.20–22 To determine the most suitable gas for EOR application from laboratory investigations, we need knowledge of the physical and chemical interaction between gas, reservoir oil, and formation rock; and information on the recovery potential for various injection gases for a targeted oil. The test oil selected for this study was from the Senlac reservoir (14° API) located in northwest Saskatchewan (Lloydminster area). The PVT properties for the oil/injection gas mixtures were measured and compared. A comparative study of the oil recovery behavior for Senlac dead oil and Senlac reservoir fluid was carried out with different injection gases to assess their relative effectiveness for EOR. Senlac Reservoir Geology The Senlac oil pool is located within the lower Cretaceous sand/shale sequence of the Mannville Group. The Mannville thickens northward and lies unconformably on the Upper Devonian Carbonates of the Saskatchewan Group. The trapping mechanism for the oil is mainly stratigraphic. The lower Lloydminster oil reservoir is a wavy, laminated, very fine- to fine-grained, well sorted, and generally unconsolidated sandstone. It exhibits uniform dark oil staining throughout, interrupted by a number of shale beds of 2 to 9 m (6 to 27 ft) thick, which are distributed over the entire reservoir. The reservoir is overlain by a shale/siltstone/sandstone sequence and lies on a 3 m (9 ft) thick coal seam. The detailed reservoir (Senlac) data and operating characteristics are provided in Ref. 5. The reservoir temperature is 28°C (82.4°F) and the reservoir pressure varies between 2.5 and 4.1 MPa (363 and 595 psia). The virgin pressure of the reservoir at discovery was 5.4 MPa (783 psia) and the gas/oil ratio (GOR) was 16.2 sm3/m3 (89.8 sft3 /bbl). The reservoir matrix has a porosity of about 27.7% by volume and permeability of about 2.5 mD. The average water saturation is about 32% pore volume (PV). The pattern configuration for oil production is five-spot on a 16.2 ha (40 acre) drainage area. The estimated primary and secondary (solution gas and waterflood) recovery is 5.5% of the initial oil in place. Experiment Wellhead Dead Oil and Brine. Senlac wellhead dead oil and formation brine (from Well 16-35-38-27 W3M) were supplied by Wascana Energy, Inc. The oil was cleaned for the experiments by removal of basic sediment and water (BS&W) through high-speed centrifugation. The chemical and physical properties of cleaned Senlac stock tank oil are shown in Table 1. The formation brine was vacuum filtered twice to remove iron contamination from the sample barrels.

Summary This article presents applications of deterministic and conditional geostatistical reservoir characterization methods to the heterogeneous carbonates of the upper Shuaiba formation in Daleel field, Oman. High-resolution reservoir descriptions based on the integration of logs, core, pressure transient tests, geology, and seismic data are constructed; and upscaled for use in reservoir simulation models to history match field performance data. Generally, geostatistical techniques combined with geology and proper upscaling of permeability heterogeneity yield best results without artificial alterations in various fluid and rock properties. Although acceptable history matches can be obtained with compromised less-detailed reservoir descriptions, these require modifications to reservoir data beyond reasonable ranges. Only detailed and concise reservoir descriptions result in history matches that are consistent with a variety of measured data sources. Introduction Reservoir characterization has gained a new momentum in the past decade, largely due to the introduction of geostatistical methods to the petroleum industry and rapid progress made in their advancement.1 The keen interest in reservoir characterization arises because it is well recognized that reservoir heterogeneity has a profound affect on all phases of hydrocarbon recovery, ranging from oil in-place calculations to sweep and conformance efficiency determination of various injection processes. Thus, any improved understanding of a reservoir will aid in better management and better exploitation of its hydrocarbon recovery potential. The challenge in understanding and predicting reservoir performance is two-fold: first, to describe reservoir geologic heterogeneities realistically and quantitatively, and second to model reservoir flow behavior in the presence of all heterogeneities accurately and efficiently.2 While large-scale reservoir features (such as main layers or major faults) can be described by deterministic techniques, less-correlated medium-scale and more-chaotic small-scale heterogeneities may be characterized by geostatistical methods or related interpolative techniques. This is especially true for estimating interwell reservoir properties based on a limited amount of information available at wells. The approaches to reservoir characterization fall into three categories: deterministic, stochastic, and combination of the two. The deterministic approach has been in use for several decades and ample success with it has been reported. The interwell properties are generally interpolated or extrapolated using algorithms based on the inverse-distance-square principle or variations of it. Usually, adjustments to the number of layers, gridblock properties, relative permeabilities, and even fluid properties are made in order to history match field performance. Some of these adjustments are warranted and some are solely knobs that are arbitrarily tuned in simulation models without physical bases. Thus, the resulting reservoir models may lack reliability and predictive capability. Geostatistical methods, however, generate multiple realizations of reservoir heterogeneity that honor available data, but differ from one another by interwell properties where direct information is not available. The data used in these models are by in large of static nature coming mainly from cores, logs, and seismic attribute extractions. Dynamic information, such as pressure transient tests and production data, are usually excluded from explicit use in geostatistical reservoir characterization, primarily due to difficulty on how to best integrate them a priori into such models. However, recent advances have been made for direct inclusion of this dynamic information through the techniques of simulated annealing3 or direct volume-averaged upscaling.4 Nevertheless, these geostatical reservoir descriptions are capable of capturing detailed geology more realistically and of producing acceptable history matches to field performance data without artificial alterations to various reservoir or fluid properties.5–10 This article applies both methods of deterministic and geostatistical reservoir characterizations to describe and history match the primary recovery performance of a complex carbonate reservoir in Daleel field, Oman. This is a comparative study in an attempt to identify an applicable description method for this field to aid in its exploitation. The deterministic model investigates effects of layering and fluid bubblepoint pressure on production performance. The geostatistical approaches model detailed reservoir heterogeneity and evaluate the importance of proper representation of heterogeneity in flow simulations. During the course of the study, new or alternate approaches for various elements of reservoir characterization techniques have been developed, which are also included. Background Field Description. The reservoir of Daleel field is an elongated carbonate shoal sands and back carbonates in the upper Shuaiba formation. Five geographical sedimentary environments of protected back shoal, shoal, shoal margin slope, inner shelf, and outer shelf comprise the formation. The productive portion of the reservoir is situated in the protected back shoal region (central part of the carbonate mound) and its marginal parts are located in regions with alternating cycles of shoal and shelf sequences. The reservoir is a stratigraphic-structural oil trap accumulation. Bioclastic peloidal packstone and wackstone form the main reservoir sedimentary material in this field. Repeated upward shallowing parasequence cycles, which relate to the geographical sedimentary environment, are recognized on wireline responses. These parasequence boundaries may be considered as synchronous surfaces for interwell correlation. Detailed core and thin section studies have identified 12 lithofacies in the upper Shuaiba, ranging from coarse grain porous limestone to argillaceous lime and lime mudstone. Microstylolites, burrowing and other forms of diagenesis are common. Therefore, pore/throat size distribution and their connectivity as influenced by secondary diagenesis processes mainly control porosity and permeability developments. Significant changes in these lithofacies occur laterally and vertically, and there is an important tightly consolidated discontinuous lime mudstone deposit in the middle of the productive upper zone in the central part of the field.

Summary X-ray computed microtomography (XMT) is used for high-resolution, nondestructive imaging and has been applied successfully to geologic media. Despite the potential of XMT to aid in formation evaluation, currently it is used mostly as a research tool. One factor preventing more widespread application of XMT technology is limited accessibility to microtomography beamlines. Another factor is that computational tools for quantitative image analysis have not kept pace with the imaging technology itself. In this paper, we present a new grain-based algorithm used for network generation. The algorithm differs from other approaches because it uses the granular structure of the material as a template for creating the pore network rather than operating on the voxel set directly. With this algorithm, several advantages emerge: the algorithm is significantly faster computationally, less dependent on image resolution, and the network structure is tied to the fundamental granular structure of the material. In this paper, we present extensive validation of the algorithm using computer-generated packings. These analyses provide guidance on issues such as accuracy and voxel resolution. The algorithm is applied to two sandstone samples taken from different facies of the Frontier Formation in Wyoming, USA, and imaged using synchrotron XMT. Morphologic and flow-modeling results are presented. Introduction Subsurface transport processes such as oil and gas production are multiscale processes. The pore scale governs many physical and chemical interactions and is the appropriate characteristic scale for the fundamental governing equations. The continuum scale is used for most core or laboratory scale measurements (e.g., Darcy velocity, phase saturation, and bulk capillary pressure). The field scale is the relevant scale for production and reservoir simulation. Multiscale modeling strategies aim to address these complexities by integrating the various length scales. While pore-scale modeling is an essential component of multiscale modeling, quantitative methods are not as well-developed as their continuum-scale counterparts. Hence, pore-scale modeling represents a weak link in current multiscale techniques. The most fundamental approach for pore-scale modeling is direct solution of the equations of motion (along with other relevant conservation equations), which can be performed using a number of numerical techniques. The finite-element method is the most general approach in terms of the range of fluid and solid mechanics problems that can be addressed. Finite-difference and finite-volume methods are more widely used in the computational fluid dynamics community. The boundary element method is very well suited for low-Reynolds number flow of Newtonian fluids (including multiphase flows). Finally, the lattice-Boltzmann method has been favored in the porous-media community because it easily adapts to the complex geometries found in natural materials. A less rigorous approach is network modeling, which gives an approximate solution to the governing equations. It requires discretization of the pore space into pores and pore throats, and transport is modeled by imposing conservation equations at the pore scale. Network modeling involves two levels of approximation. The first is the representation of the complex, continuous void space as discrete pores and throats. The second is the approximation to the fluid mechanics when solving the governing equations within the networks. The positive tradeoff for these significant simplifications is the ability to model transport over orders-of-magnitude larger characteristic scales than is possible with direct solutions of the equations of motion. Consequently, the two approaches (rigorous modeling of the conservation equations vs. network modeling) have complementary roles in the overall context of multiscale modeling. Direct methods will remain essential for studying first-principles behavior and subpore-scale processes such as diffusion boundary layers during surface reactions, while network modeling will provide the best avenue for capturing larger characteristic scales (which is necessary for modeling the pore-to-continuum-scale transition). This research addresses one of the significant hurdles for quantitative network modeling: the use of high-resolution imaging of real materials for quantitative flow modeling. We focus in particular on XMT to obtain 3D pore-scale images, and present a new technique for direct mapping of the XMT data onto networks for quantitative modeling. This direct mapping (in contrast to the generation of statistically equivalent networks) ensures that subtle spatial correlations present in the original material are retained in the network structure.

Abstract The Xiong’an New Area is located at the western Bohai Bay Basin, 150 km south of Beijing, China. The area has tremendous high heat flow value within the sedimentary layer, and the average value can reach 90 mW·m-2 within the Niutuozhen Uplift. However, combining the basal heat flow at the top of the metamorphic layer with the heat flow value which was contributed by the radiogenic heat production from the overlying formation, the surface heat flow value was only 65.1 mW·m-2 in this area. Thus, the heat flow value within the sedimentary layer was greatly influenced by other factors. In this study, based on the continuous temperature measurements data from 4 boreholes, thermos-physical parameters (conductivity, radioactive heat production, density, and heat capacity) from 90 rock sample measurements, and the regional stratigraphic development, a two-dimensional thermal-hydraulic modelling was carried out to study the influence of the heat refraction and groundwater convection on the heat flow value. According to calculation results, the heat flow disturbance caused by heat refraction was 10 mW·m-2, and the disturbance value was 20 mW·m-2 for the groundwater convection. Furthermore, when the high-permeability layer thickness was a certain value, with the increasing high-permeability layer buried depth, the influence of the groundwater convection on the temperature field which was used for the heat flow calculation became weak. While when the high-permeability layer buried depth was set up, the influence of the groundwater convection on the above temperature field became stronger with the increasing high-permeability layer thickness.

O trabalho apresenta uma resenha da obra “Geognostisches Gemälde von Brasilien und wahrscheinlichesMuttergestein der Diamanten “ de Wilhelm Ludwig von Eschwege por ocasião do sesquicentenário da suamorte em 1o de fevereiro de 2005. A obra foi publicada, em pequena tiragem, em 1822. Trata inicialmentedos grandes divisores de água: um de direção aproximada leste – oeste, separando a bacia do rio Amazonasdas dos rios Paraná e Paraguai, que Eschwege batiza de “Serra das Vertentes”, o outro divisor separa a baciado Rio São Francisco dos rios que correm diretamente ao Oceano Atlântico o qual chama de “Serra doEspinhaço”, incluindo nela a Serra da Mantiqueira. Em segundo lugar apresenta um esquema estratigráficobaseado nos modelos usados na Europa, como, por exemplo, aquele proposto em 1787 por AbrahamGottlieb Werner, professor da Academia de Minas de Freiberg na Alemanha. A Primeira FormaçãoPrimitiva é formada pelo embasamento cristalino, a Segunda Formação Primitiva corresponde às seqüênciassupracrustais dobradas (representadas pelos Supergrupos Rio das Velhas, Minas e Espinhaço), a Terceira oude Transição abrange essencialmente o atual Grupo Bambui e uma quarta subdivisão reúne depósitossuperficiais como aluviões e coberturas terciárias e quarternárias. Percebe-se que suas idéias a respeito dageologia do Brasil são fortemente influenciadas pela escola netunista de Werner. Descreve aindamacroscopicamente os principais tipos de rocha encontrados no Brasil, define os novos termos “itacolumito”e “itabirito” e introduz o termo “tapanhoacanga” na nomenclatura geológica, todos com suas localidadestipo.Tapanhoacanga, hoje reduzida para canga, é de origem indígena de tapanhu = escravo negro e acanga= cabeça (ou a = cabeça e canga = osso). A última parte do “Quadro geognóstico... “ trata da ocorrência dosdiamantes no Brasil e de sua possível rocha matriz, na sua opinião formados em concreções limoníticasoriginadas das rochas ferruginosas da Segunda Formação Primitiva.Palavras-chave: História da Geologia, Quadrilátero Ferrífero, Serra do Espinhaço, estratigrafia precambriana,itabirito, itacolumito, canga, diamantes ABSTRACT: ESCHWEGE’S “GEOGNOSTICAL SKETCH OF BRAZIL AND THE PROBABLE SOURCE ROCK OFDIAMONDS”: BRIEF COMMENTS ON HIS VISION OF BRAZILIAN GEOLOGY. This small brochure waspublished in 1822 by the German geologist Wilhem Ludwig von Eschwege (1777 – 1855) and is nowtranslated to Portuguese for the first time completely as a memorial of his passing away 150 years ago.Initially, Eschwege reports on the physical geography of Brazil and suggests the names “Serra das Vertentes”(Watershed Mountains) and “Serra do Espinhaço” (Backbone Ridge), running East – West the first and North– South the second, separating the great hydrographic basins in Brazil. A main chapter is dedicated to a veryfirst proposal of a stratigraphic scheme based on European models of the time and heavily influenced by A.G. Werner, the principal protagonist of the neptunism, which interpreted all rocks as being precipitated fromaqueous solutions. He distinguishes four stratigraphic divisions: the First Primitive Formation containinggranite, gneiss, and mica schist, corresponding in more modern terms to the crystalline basement; the SecondPrimitive Formation is formed by itacolumite (quartzite), itabirite (iron formation) and schist, representedby the Rio das Velhas, Minas, and Espinhaço supergroups. The third or Transitional Formation composed byslates, quartz schist, greywacke, and massive limestone corresponds to the Macaúbas and Bambui groups. Thefourth and uppermost formation encloses all superficial deposits, such as alluvial, river gravels and a peculiarferruginous conglomerate called by the native tapanhoacanga, which means Negro head. His argumentationis heavily influenced by neptunistic thinking. Eschwege still describes in great detail the principal rock types,as known at this time in Brazil and introduces the terms itacolumite, itabirite and (tapanhoa)canga into thegeological nomenclature. The second part is dedicated to the occurrence, distribution and origin of Braziliandiamonds. He considers that they are formed within any rock of his Second Primitive Formation, due to theoccasional founding of limonitic concretions with inclusions of diamonds.Keywords: History of geology, Quadril